1. Field of the Invention
Embodiments of the present invention generally relate to subsea production systems. Embodiments of the present invention further pertain to methods for managing hydrate formation in subsea equipment such as production lines.
2. Description of the Related Art
Over the last thirty years, the search for oil and gas offshore has moved into progressively deeper waters. Wells are now commonly drilled at depths of several hundred feet and even several thousand feet below the surface of the ocean. In addition, wells are now being drilled in more remote offshore locations.
The drilling and maintenance of deep and remote offshore wells is expensive. In an effort to reduce drilling and maintenance expenses, remote offshore wells are oftentimes drilled in clusters. A grouping of wells in a clustered subsea arrangement is sometimes referred to as a “subsea well-site.” A subsea well-site typically includes producing wells completed for production at one and oftentimes more pay zones. In addition, a well-site will oftentimes include one or more injection wells to aid in maintaining in-situ pressure for water drive and gas expansion drive reservoirs.
The grouping of subsea wells facilitates the gathering of production fluids into a local production manifold. Fluids from the clustered wells are delivered to the manifold through flowlines called “jumpers.” From the manifold, production fluids may be delivered together to a gathering and separating facility through a production line, or “riser.” For well-sites that are in deeper waters, the gathering facility is typically a floating production storage and offloading vessel, or “FPSO.”
The clustering of wells also allows for multiple control lines and chemical treatment lines to be run from the ocean surface, downward to the clustered wells. These lines are commonly bundled into one or more “umbilicals.” The umbilical terminates at an “umbilical termination assembly,” or “UTA,” at the ocean floor. A control line may carry hydraulic fluid used for controlling items of subsea equipment such as subsea distribution units (“SDU's”), manifolds and trees. Such control lines allow the actuation of valves, chokes, downhole safety valves and other subsea components from the surface. In addition, the umbilical may transmit chemical inhibitors to the ocean floor and then to equipment of the subsea processing system. The inhibitors are designed and provided in order to ensure that flow from the wells is not affected by the formation of solids in the flow stream such as hydrates, waxes and scale. Electrical lines may also be included in an umbilical for monitoring or control of subsea functions.
In cold water production environments, the management of hydrates in subsea equipment is important. Those of ordinary skill in the art will understand that hydrates may form along subsea wellheads and risers, restricting the flow of production fluids to the gathering facility. Hydrates are crystals consisting of water and gas molecules. The water molecules in produced fluid form a lattice structure into which many types of gas molecules may fit. Examples of such gas molecules include H2S, CO2 and CH4. Hydrates that form as a result of H2S, CO2 and non-hydrocarbon gases are generically referred to as “gas hydrates.” Hydrates that form as a result of natural gas (such as CH4) in the production fluids may be more specifically referred to as “natural gas hydrates.” Natural gas hydrates may form by water entrapping natural gases and associated liquids in a ratio of 85 mole % water to 15% hydrocarbons. Thus, when production fluids include water and gas molecules, and when such production fluids are at low temperatures and high pressures, the formation of hydrates in subsea equipment may restrict the flow of production fluids to a gathering facility.
In a production line, hydrate masses tend to form at the hydrocarbon-water interface. The hydrates may accumulate as fluid flow pushes the hydrate masses downstream. The hydrate mass can grow to a size that creates a “plug” or restriction to fluid flow. The resulting porous hydrate plugs have the unusual ability to transmit some degree of gas pressure, while acting as a liquid flow hindrance.
In order to manage hydrate formation, the operator may use jumpers and production lines that are insulated. In addition, the operator may inject chemical “inhibitors” at or near the subsea wellhead, such as into the manifold. Gas hydrates may be thermodynamically suppressed by adding materials such as salts or glycols, which operate as “antifreeze.” Commonly, methanol or methyl ethylene glycol (MEG) may be injected at the subsea tree as the antifreeze material. Inhibitors are oftentimes introduced during well startup. The inhibitor will continue to be injected until the subsea equipment is sufficiently warmed by the produced fluids such that the risk of hydrate formation is abated. Inhibitors may also be introduced prior to a planned shut-in of a wellhead. In that instance, the injected methanol will commingle with the produced fluids before shut-in so that hydrate formation is avoided during the subsequent cooldown.
The management of hydrates becomes more difficult when production is shut in unplanned. In this instance, the operator may not have time to inject an inhibitor so as to “inhibit” produced fluids resident in the production line. This may occur, for example, where a gas compressor suddenly goes down. To prevent hydrate formation in the production line in this instance, it is known to provide a second alternate production line. A displacement fluid is injected into the second production line so as to circulate out the uninhibited produced fluids before hydrate formation occurs. Displacement is commonly accomplished by pushing a pig through the line. The pig is launched into the second production line and may be driven by a dehydrated crude out to the production manifold. The pig is then pumped through the production manifold and returned to the gathering facility through the first, or “live,” production line. Displacement is completed before the uninhibited production fluids cool down below the hydrate formation temperature, thereby preventing the creation of a hydrate blockage in the line.
For relatively small offshore developments, the cost of a second production line can be prohibitive. Therefore, there is a need for an alternate method of displacing production fluids from a production line in order to manage hydrate formation.